Well treatment fluids are routinely used in stimulation operations to enhance the recovery of hydrocarbons from subterranean formations. Such operations include acidizing and hydraulic fracturing. Much interest has been focused on methods for improving downhole placement of well treatment fluids during stimulation operations in order to create highly conductive channels over large areas.
The treatment design of a hydraulic fracturing operation for a conventional reservoir generally requires fracturing fluid to reach maximum viscosity as it enters the fracture. A long primary bi-wing fracture is typically created perpendicular to the minimum stress orientation. Pumping of fracturing fluid into the wellbore usually just extends the planar or primary fracture; secondary fractures near the wellbore are limited. Fracturing treatments which create predominately long planar fractures are characterized by a low contacted fracture face surface area, i.e., low stimulated reservoir volume (SRV).
Low viscosity fluids known as slickwater are often used in the stimulation of low permeability formations, including tight gas reservoirs, such as shale formations. Such reservoirs are typically characterized by a permeability less than or equal to 1.0 mD and exhibit a complex natural fracture network. To effectively access tight formations, wells are often drilled horizontally and then subjected to one or more fracture treatments to stimulate production. Fractures propagated with low viscosity fluids exhibit smaller fracture widths than those propagated with higher viscosity fluids. While fracture SRV and complexity is increased, secondary fractures created by the operation are near to the wellbore. Slickwater fracturing is generally considered to be inefficient in the opening or creation of complex network of fractures farther away from the wellbore. Thus, while SRV is increased in slickwater fracturing, production is high only initially and then drops rapidly to a lower sustained production since there is little access to hydrocarbons far field from the wellbore.
Recovery of entrapped oil or gas can be accelerated by increasing the effective wellbore area within the formation. In the past, methods have been developed to divert the flow of treatment fluids from the higher permeability sections of the formation to the lower permeability sections. For instance, chemical diverting agents have been used to temporarily block the high permeability intervals within the formation and divert stimulation fluids into the desired low permeability intervals by increasing flow resistance inside the created channels. It is desirable for these agents to be stable at the bottomhole temperature and also to be removable from the formation rapidly after the treatment in order to eliminate any potential damage to the high permeability intervals.
Representative chemical diverting agents used in the past are viscous gels or foams such as blends of viscoelastic surfactants and/or polymer based gels such as hydroxyethylcellulose (HEC) and hydropropyl guar gum. Polymer based gels often result in formation damage caused by polymeric residue while viscoelastic surfactants often cannot discriminate between zones with various permeabilities. Further, temperature limitations for such systems are generally around 200° F. Other chemical diverters used in the past have failed to control the flow of fluid used in acidizing operations. Oil-soluble naphthalenes, crushed limestone, sodium tetraborate, oyster shells, gilsonite, perilite and paraformaldehyde have also been reported for use as chemical diverters. Such materials have been shown to be only useful in wells having a bottom hole temperature of 175° F. or less.
Chemical diverters have also focused on materials which are acid soluble. For instance, solid organic acid flakes, such as polylactic acid flakes, have been reported to be useful for acid diversion. While such materials hydrolyze to release acid, a high volume of water is required to completely hydrolyze the material and to ensure full conversion of the solid materials into acid. Failure to remove the solids causes formation damage.
Alternatives have therefore been sought for diverting agents which are suitable for use at high bottom hole temperatures and which do not cause formation damage.
It should be understood that the above-described discussion is provided for illustrative purposes only and is not intended to limit the scope or subject matter of the appended claims or those of any related patent application or patent. Thus, none of the appended claims or claims of any related application or patent should be limited by the above discussion or construed to address, include or exclude each or any of the above-cited features or disadvantages merely because of the mention thereof herein.